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Table of Contents

 

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-Q

 


 

(Mark one)

 

x      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended March 31, 2014

 

or

 

o         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from            to           

 

Commission File Number: 001-36264

 

RSP Permian, Inc.

(Exact name of registrant as specified in its charter)

 

Delaware

 

90-1022997

State or other jurisdiction of
incorporation or organization

 

(I.R.S. Employer
Identification Number)

 

 

 

3141 Hood Street, Suite 500

Dallas, Texas

 

75219

(Address of principal executive offices)

 

(Zip code)

 

(214) 252-2700
(Registrant’s telephone number, including area code)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x  No o

 

Indicate by check mark whether the registrant has submitted electronically and posted to its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Registration S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x  No o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer

o

Accelerated filer o

Non-accelerated filer

x (Do not check if a smaller reporting company)

Smaller reporting company o

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.): Yes o  No x

 

The registrant had 72,500,000 shares of common stock outstanding at May 13, 2014.

 

 

 



Table of Contents

 

TABLE OF CONTENTS

 

 

 

Page

 

 

 

Glossary of Certain Terms and Conventions Used Herein

1

 

 

Cautionary Statement Concerning Forward-Looking Statements

3

 

 

 

PART I. FINANCIAL INFORMATION

 

 

 

Item 1.

Financial Statements

 

 

 

 

 

Consolidated Balance Sheets as of March 31, 2014 and December 31, 2013

4

 

 

 

 

Consolidated Statements of Operations for the Three Months Ended March 31, 2014 and 2013

5

 

 

 

 

Consolidated Statement of Changes in Equity for the Three Months Ended March 31, 2014

6

 

 

 

 

Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2014 and 2013

7

 

 

 

 

Notes to Consolidated Financial Statements

8

 

 

 

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

24

 

 

 

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

37

 

 

 

Item 4.

Controls and Procedures

39

 

 

 

PART II. OTHER INFORMATION

 

 

 

Item 1.

Legal Proceedings

40

 

 

 

Item 1A.

Risk Factors

40

 

 

 

Item 6.

Exhibits

40

 



Table of Contents

 

GLOSSARY OF CERTAIN TERMS AND CONVENTIONS USED HEREIN

 

The following are abbreviations and definitions of certain terms used in this Quarterly Report on Form 10-Q:

 

Bbl.” A standard barrel containing 42 U.S. gallons.

 

Bbls/d.” Bbls per day.

 

Boe.” One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

 

Boe/d.” One Boe per day.

 

Btu.” One British thermal unit, which is the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

 

Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

 

Differential.” An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

 

Dry natural gas.” A natural gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.

 

Dry hole” or “dry well.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

 

Exploitation.” A development or other project that may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

 

Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

 

Formation.” A layer of rock that has distinct characteristics that differs from nearby rock.

 

Gross acres” or “gross wells.” The total acres or wells, as the case may be, in which a working interest is owned.

 

Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

 

MBbl.” One thousand barrels.

 

MBoe.” One thousand Boe.

 

Mcf.” One thousand cubic feet.

 

Mcf/d.” One Mcf per day.

 

MMBbls.” One million barrels.

 

MMBoe.” One million Boe.

 

MMBtu.” One million British thermal units.

 

MMcf.” One million cubic feet.

 

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Table of Contents

 

Net production.” Production that is owned by us less royalties and production due others.

 

NGLs.” Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline.

 

NYMEX.” The New York Mercantile Exchange.

 

Operator.” The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.

 

Plugging.” The sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface.

 

Realized price.” The cash market price less all expected quality, transportation and demand adjustments.

 

Recompletion.” The completion for production of an existing wellbore in another formation from which the well has been previously completed.

 

Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

 

SEC.” The United States Securities and Exchange Commission

 

Spot market price.” The cash market price without reduction for expected quality, transportation and demand adjustments.

 

Undeveloped acreage.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

 

Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

 

We,” “our,” “us” or like terms and the “Company” refer to RSP Permian, Inc. and its subsidiary, RSP Permian, L.L.C.

 

Wellbore.” The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.

 

Working interest.” The right granted to the lessee of a property to explore for and to produce and own oil, natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

 

WTI.” West Texas Intermediate.

 

The terms “development project,” “development well,” “exploratory well,” “proved developed reserves,” “proved reserves” and “reserves” are defined by the SEC.

 

Information presented in this Quarterly Report on Form 10-Q on a pro forma basis gives effect to the completion of the corporate reorganization and acquisitions in connection with our initial public offering completed in January 2014, each as described under “Part I, Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operation—Initial Public Offering.”

 

2



Table of Contents

 

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

 

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us.  While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections.  Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, the volatility of commodity prices, product supply and demand, competition, access to and cost of capital, uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future, the assumptions underlying production forecasts, the quality of technical data, environmental and weather risks, including the possible impacts of climate change, the ability to obtain environmental and other permits and the timing thereof, government regulation or action, the costs and results of drilling and operations, the availability of equipment, services, resources and personnel required to complete the Company’s operating activities, access to and availability of transportation, processing and refining facilities, the financial strength of counterparties to the Company’s credit facility and derivative contracts and the purchasers of the Company’s production, and acts of war or terrorism. For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013.

 

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

 

3



Table of Contents

 

PART I.  FINANCIAL INFORMATION

 

Item 1.   Financial Statements.

 

RSP PERMIAN, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

 

 

March 31, 2014

 

December 31, 2013

 

 

 

(In thousands)

 

ASSETS

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

Cash and cash equivalents

 

$

10,737

 

$

13,234

 

Accounts receivable

 

34,819

 

26,346

 

Accounts receivable, related party

 

7,107

 

3,672

 

Escrow receivable

 

 

3,197

 

Escrow deposit

 

15

 

15

 

Derivative instruments

 

225

 

671

 

Total current assets

 

52,903

 

47,135

 

PROPERTY, PLANT AND EQUIPMENT

 

 

 

 

 

Oil and natural gas properties, successful efforts method

 

1,573,057

 

595,486

 

Accumulated depletion

 

(95,899

)

(88,514

)

Total oil and natural gas properties, net

 

1,477,158

 

506,972

 

Other property and equipment, net

 

12,654

 

9,316

 

Total property, plant and equipment

 

1,489,812

 

516,288

 

LONG-TERM ASSETS

 

 

 

 

 

Derivative instruments

 

440

 

1,078

 

Restricted cash

 

150

 

150

 

Other assets

 

28,830

 

23,004

 

Total long-term assets

 

29,420

 

24,232

 

TOTAL ASSETS

 

$

1,572,135

 

$

587,655

 

LIABILITIES AND STOCKHOLDERS’/MEMBERS’ EQUITY

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

Accounts payable

 

$

26,339

 

$

18,548

 

Accrued expenses

 

23,961

 

10,460

 

Interest payable

 

385

 

296

 

Derivative instruments

 

4,156

 

1,562

 

Total current liabilities

 

54,841

 

30,866

 

LONG-TERM LIABILITIES

 

 

 

 

 

Asset retirement obligations

 

4,805

 

2,584

 

Derivative instruments

 

207

 

43

 

Term loan

 

 

70,000

 

Revolving credit facility

 

110,000

 

58,155

 

NPI payable

 

 

36,931

 

Deferred taxes

 

332,315

 

2,195

 

Total long-term liabilities

 

447,327

 

169,908

 

Total liabilities

 

502,168

 

200,774

 

STOCKHOLDERS’/MEMBERS’ EQUITY

 

 

 

 

 

Members’ equity

 

 

386,881

 

Common stock, $.01 par value; 300,000,000 shares authorized, 72,500,000 shares issued and outstanding at March 31, 2014; no shares authorized, issued or outstanding at December 31, 2013

 

725

 

 

Additional paid-in capital

 

1,196,772

 

 

Accumulated deficit

 

(127,530

)

 

Total stockholders’/members’ equity

 

1,069,967

 

386,881

 

TOTAL LIABILITIES AND STOCKHOLDERS’/MEMBERS’ EQUITY

 

$

1,572,135

 

$

587,655

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

4



Table of Contents

 

RSP PERMIAN, INC.

CONSOLIDATED STATEMENT OF OPERATIONS

(Unaudited)

 

 

 

Three Months Ended March 31,

 

 

 

2014

 

2013

 

 

 

(In thousands, except per share data)

 

REVENUES

 

 

 

 

 

Oil sales

 

$

51,471

 

$

21,923

 

Natural gas sales

 

2,206

 

1,165

 

NGL sales

 

4,081

 

1,567

 

Total revenues

 

57,758

 

24,655

 

OPERATING EXPENSES

 

 

 

 

 

Lease operating expenses

 

$

7,063

 

$

3,355

 

Production and ad valorem taxes

 

3,876

 

1,636

 

Depreciation, depletion and amortization

 

16,361

 

10,202

 

Asset retirement obligation accretion

 

29

 

25

 

Exploration

 

756

 

63

 

General and administrative expenses

 

17,016

 

555

 

Total operating expenses

 

45,101

 

15,836

 

(Gain) on sale of assets

 

 

(6,129

)

OPERATING INCOME

 

$

12,657

 

$

14,948

 

OTHER INCOME (EXPENSE)

 

 

 

 

 

Other income

 

$

310

 

$

199

 

Loss on derivative instruments

 

(4,153

)

(1,657

)

Interest expense

 

(1,131

)

(624

)

Total other expense

 

(4,974

)

(2,082

)

INCOME BEFORE TAXES

 

7,683

 

12,866

 

INCOME TAX EXPENSE

 

(135,213

)

 

NET INCOME (LOSS)

 

$

(127,530

)

$

12,866

 

 

 

 

 

 

 

Loss per common share:

 

 

 

 

 

Basic

 

$

(2.03

)

 

 

Diluted

 

$

(2.03

)

 

 

Weighted average shares outstanding:

 

 

 

 

 

Basic

 

62,904

 

 

 

Diluted

 

62,904

 

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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Table of Contents

 

RSP PERMIAN, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’/ MEMBERS’ EQUITY

(Unaudited)

 

 

 

Members’
Equity

 

Issued Shares
of Common
Stock

 

Common
Stock

 

Additional
Paid-in
Capital

 

Accumulated
Deficit

 

Total
Stockholders’
Equity/
Members’
Equity

 

 

 

(In thousands)

 

BALANCE AT DECEMBER 31, 2013

 

$

386,881

 

 

$

 

$

 

$

 

$

386,881

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Distribution of net assets to predecessor owner, including cash of $1,663

 

(21,147

)

 

 

14,168

 

 

(6,979

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The corporate reorganization

 

(365,734

)

 

 

365,734

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

RSP Permian Holdco, L.L.C.’s contributions of interests in RSP Permian, L.L.C. in exchange for RSP Permian, Inc.’s common stock

 

 

63,275

 

633

 

(633

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ted Collins, Jr., Wallace Family Partnership, LP, Collins & Wallace Holdings, LLC, Pecos Energy Partners, L.P. and ACTOIL LLC’s contributions in exchange for RSP Permian, Inc.’s common stock

 

 

 

 

642,436

 

 

642,436

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Shares of common stock sold in initial public offering net of offering costs

 

 

9,225

 

92

 

163,052

 

 

163,144

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity-based compensation

 

 

 

 

12,015

 

 

12,015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss

 

 

 

 

 

(127,530

)

(127,530

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BALANCE AT MARCH 31, 2014

 

$

 

72,500

 

$

725

 

$

1,196,772

 

$

(127,530

)

$

1,069,967

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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Table of Contents

 

RSP PERMIAN, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

 

 

 

Three Months Ended March 31,

 

 

 

2014

 

2013

 

 

 

(In thousands)

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income (loss)

 

$

(127,530

)

$

12,866

 

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

Depreciation, depletion and amortization

 

16,361

 

10,070

 

Abandoned equipment and intangibles

 

 

1

 

Accretion of asset retirement obligations

 

29

 

25

 

Equity based compensation

 

12,015

 

 

Amortization of loan fees

 

208

 

131

 

Deferred income taxes

 

135,213

 

 

Equity in earnings of investment

 

 

30

 

(Gain) on sale of assets

 

 

(6,129

)

Loss on derivative instruments

 

4,153

 

1,657

 

Net cash payments on settled derivatives

 

(312

)

(109

)

Changes in operating assets and liabilities:

 

 

 

 

 

Accounts receivable and accounts receivable from related parties

 

(7,529

)

2,464

 

Other assets

 

(9,039

)

(6,387

)

Interest payable

 

89

 

(227

)

Accounts payable

 

8,350

 

365

 

Accrued expenses

 

(1,007

)

(172

)

Net cash provided by operating activities

 

$

31,001

 

$

14,585

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Proceeds from sale of assets

 

 

115,339

 

Additions to other property and equipment

 

(1,294

)

255

 

Additions to oil and natural gas properties

 

(177,530

)

(57,237

)

Net cash provided by (used in) investing activities

 

$

(178,824

)

$

58,357

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Issuance of common stock

 

163,144

 

 

Distributions

 

(1,663

)

(29,805

)

Borrowings under long-term debt

 

110,000

 

 

Payments on long-term debt

 

(126,155

)

(85,000

)

NPI payable

 

 

20,349

 

Net cash provided by (used in) financing activities

 

$

145,326

 

$

(94,456

)

NET CHANGE IN CASH

 

$

(2,497

)

$

(21,514

)

CASH AT BEGINNING OF YEAR

 

$

13,234

 

$

52,263

 

CASH AT END OF YEAR

 

$

10,737

 

$

30,749

 

SUPPLEMENTAL CASH FLOW INFORMATION

 

 

 

 

 

Cash paid for interest

 

$

624

 

$

3,420

 

NON-CASH ACTIVITIES

 

 

 

 

 

Assets purchased included in accounts payable and accrued expenses

 

$

14,442

 

$

2,202

 

Asset retirement obligation acquired

 

$

2,412

 

$

 

Common stock issued for oil and gas properties

 

$

677,402

 

$

 

Deferred tax liabilities recorded for oil and gas property acquisitions

 

$

195,777

 

$

 

Elimination of NPI payable

 

$

36,931

 

$

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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Table of Contents

 

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

 

Organization and Description of the Business

 

RSP Permian, L.L.C., a Delaware limited liability company (“RSP LLC”), was formed on October 18, 2010 by its management team and an affiliate of Natural Gas Partners, a family of energy-focused private equity investment funds (“NGP”). RSP LLC is engaged in the acquisition, development and operation of oil and natural gas properties. Additional background on and details of the ownership of RSP LLC are available on the Company’s Annual Report on Form 10-K for the year ended December 31, 2013.

 

On January 23, 2014, RSP Permian, Inc. (“RSP Inc.”) completed an initial public offering (the “IPO”) and on January 17, 2014, shares of RSP Inc. began trading on the New York Stock Exchange under the ticker “RSPP.” In the IPO, 23 million shares were sold at $19.50 per share, raising $449 million of gross proceeds. Of the 23 million shares, 9.2 million were shares sold by RSP Inc., resulting in approximately $163 million of net proceeds, which were used to fully repay the Company’s $70 million term loan, repay outstanding borrowings of $56 million under its revolving credit facility, make cash payments to certain existing investors as partial consideration for the properties contributed to the Company by such persons, pay cash bonuses to certain of the Company’s employees in connection with the successful completion of the IPO, and fund a portion of its capital expenditure plan. The remaining 13.8 million shares sold in the IPO were sold by selling stockholders, and the Company did not receive any proceeds from the sale of those shares.

 

In connection with the IPO, several transactions occurred that changed the structure and scope of the Company:

 

·                  Corporate Reorganization: RSP LLC was contributed to RSP Permian Holdco, L.L.C., a newly formed limited liability company, which contributed all of its interests in RSP LLC to RSP Inc. in exchange for shares of RSP Inc.’s common stock, an assignment of RSP LLC’s pro rata share of an escrow related to the Resolute Sale (as defined and described in Note 3) and cash. As a result of this reorganization, RSP LLC became a wholly owned subsidiary of RSP Inc.

·                  The Rising Star Acquisition: RSP Inc. acquired from Rising Star Energy Development Co., L.L.C., a Texas limited liability company (“Rising Star”), working interests in certain acreage and wells in the Permian Basin in which RSP LLC already had working interests in exchange for shares of RSP Inc.’s common stock and cash.

·                  The Collins and Wallace Contributions: Ted Collins, Jr. (“Collins”), Wallace Family Partnership, LP (“Wallace LP”) and Collins & Wallace Holdings, LLC, a newly formed entity that is jointly owned by Collins and Wallace LP, contributed certain working interests in the Permian Basin in which RSP LLC already had working interests in exchange for shares of RSP Inc.’s common stock and, in the case of Collins and Wallace LP, cash (such contributions, the “Collins and Wallace Contributions”). See Note 3 for additional information.

·                  The Pecos Contribution: Pecos Energy Partners, L.P. (“Pecos”), an entity owned by certain members of the Company’s management team, contributed certain working interests in acreage and wells in the Permian Basin in which RSP LLC already had a working interest in exchange for shares of RSP Inc.’s common stock.

·                  The ACTOIL NPI Repurchase:  ACTOIL, LLC (“ACTOIL”), the owner of a 25% net profits interest (“NPI”) in substantially all of RSP LLC’s oil and natural gas properties taken as a whole, contributed their 25% NPI in exchange for shares of RSP Inc.’s common stock (such contribution, the “ACTOIL NPI Repurchase”).  See Note 3 for more information.

 

Basis of Presentation

 

These financial statements have been prepared by the Company without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the audited annual financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to such rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading. These financial statements

 

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should be read together with the financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013.

 

Subsequent Events

 

The Company has evaluated subsequent events of its consolidated financial statements. There were no material subsequent events requiring additional disclosure in these financial statements.

 

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Use of Estimates

 

The preparation of the consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities in the financial statements and accompanying notes. Although management believes these estimates are reasonable, actual results could differ from these estimates. Changes in estimates are recorded prospectively. Significant assumptions are required in the valuation of proved oil and natural gas reserves that may affect the amount at which oil and natural gas properties are recorded. Estimation of asset retirement obligations (“AROs”) and valuations of derivative instruments and the fair value of incentive unit compensation also require significant assumptions. It is possible that these estimates could be revised at future dates and these revisions could be material. Depletion of oil and natural gas properties are determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price estimates.

 

Reclassifications

 

Certain reclassifications have been made to prior periods to conform to current period presentation.

 

Accounts Receivable from Related Parties

 

The Company’s accounts receivable from related parties as of March 31, 2014 and December 31, 2013 consisted of the following:

 

 

 

March 31, 2014

 

December 31, 2013

 

 

 

(In thousands)

 

Collins

 

$

3,261

 

$

 

Wallace LP

 

3,594

 

3,672

 

Collins & Wallace Holdings, LLC

 

252

 

 

 

 

$

7,107

 

$

3,672

 

 

Prior to the IPO, Collins, Wallace LP and Collins & Wallace Holdings, LLC had non-operated working interests in substantially all of the oil and natural gas assets that the Company operates. The Company considers the accounts receivable from these related parties to be fully collectible.

 

Oil and Natural Gas Properties

 

The Company uses the successful efforts method of accounting for its oil and natural gas exploration and production activities. Costs incurred by the Company related to the acquisition of oil and natural gas properties and the cost of drilling development wells and successful exploratory wells are capitalized, while the costs of unsuccessful exploratory wells are expensed when determined to be unsuccessful.

 

The Company capitalizes interest on expenditures while activities are in progress to bring the assets to their intended use for significant exploration and development projects that last more than six months. The Company did

 

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not capitalize any interest in the three months ended March 31, 2014 and 2013 as no projects lasted more than six months. Costs incurred to maintain wells and related equipment, lease and well operating costs and other exploration costs are expensed as incurred. Gains and losses arising from sales of properties are generally included as income. Unproved properties are assessed periodically for possible impairment.

 

Capitalized acquisition costs attributable to proved oil and natural gas properties and leasehold costs are depleted on a field basis based on proved reserves using the unit-of-production method. Capitalized exploration well costs and development costs, including AROs, are depleted on a field basis, based on proved developed reserves. Depletion expense for oil and natural gas producing property was $16.3 million and $10.2 million for the three months ended March 31, 2014 and 2013, respectively, and is included in depreciation, depletion and amortization in the accompanying consolidated statements of operations.

 

The Company’s oil and natural gas properties as of March 31, 2014 and December 31, 2013 consisted of the following:

 

 

 

March 31, 2014

 

December 31, 2013

 

 

 

(In thousands)

 

Proved oil and natural gas properties

 

$

1,064,430

 

$

562,019

 

Unproved oil and natural gas properties

 

508,627

 

33,467

 

Total oil and natural gas properties

 

1,573,057

 

595,486

 

Less: accumulated depletion

 

(95,899

)

(88,514

)

Total oil and natural gas properties, net

 

$

1,477,158

 

$

506,972

 

 

In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the anticipated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. As of March 31, 2014 and December 31, 2013, there were no costs capitalized in connection with exploratory wells in progress.

 

Capitalized costs are evaluated for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. To determine if a depletable unit (field) is impaired, the Company compares the carrying value of the depletable unit to the undiscounted future net cash flows by applying estimates of future oil and natural gas prices to the estimated future production of oil and natural gas reserves over the economic life of the property and deducting future costs. Future net cash flows are based upon reservoir engineers’ estimates of proved reserves.

 

For a property determined to be impaired, an impairment loss equal to the difference between the property’s carrying value and estimated fair value is recognized. Fair value, on a field basis, is estimated to be the present value of the aforementioned expected future net cash flows. Unproved properties are assessed periodically to determine whether they have been impaired. An impairment allowance is provided on an unproved property when the Company determines that the property will not be developed. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future net cash flows and fair value.  No impairment of proved property was recorded for the three months ended March 31, 2014 or 2013.

 

Natural gas volumes are converted to Boe at the rate of six Mcf of natural gas to one Bbl of oil. This convention is not an equivalent price basis and there may be a large difference in value between an equivalent volume of oil versus an equivalent volume of natural gas. NGL volumes are stated in barrels.

 

Asset Retirement Obligation

 

The Company records AROs related to the retirement of long-lived assets at the time a legal obligation is incurred and the liability can be reasonably estimated. AROs are recorded as long-term liabilities with a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability due to passage of time are generally recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.

 

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The Company estimates a fair value of the obligation on each well in which it owns an interest by identifying costs associated with the future down-hole plugging, dismantlement and removal of production equipment and facilities, and the restoration and reclamation of a field’s surface to a condition similar to that existing before oil and natural gas extraction began.

 

In general, the amount of ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date which is then discounted back to the date that the abandonment obligation was incurred using an estimated credit adjusted rate. If the estimated ARO changes, an adjustment is recorded to both the ARO and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.

 

After recording these amounts, the ARO is accreted to its future estimated value using the same assumed credit adjusted rate and the associated capitalized costs are depreciated on a unit-of-production basis.

 

The ARO consisted of the following for the periods indicated:

 

 

 

Three Months Ended
March 31, 2014

 

 

 

(In thousands)

 

Asset retirement obligation at beginning of period

 

$

2,584

 

Liabilities assumed

 

2,192

 

Accretion expense

 

29

 

Asset retirement obligation at end of period

 

$

4,805

 

 

Income Taxes

 

RSP LLC was organized as a limited liability company and treated as a flow-through entity for federal income tax purposes.  As such, taxable income and any related tax credits were passed through to its members and are included in their tax returns even though such net taxable income or tax credits may not have actually been distributed. Accordingly, provision for federal and state corporate income taxes has been made only for the operations of RSP Inc. from January 23, 2014 through March 31, 2014 in the accompanying consolidated financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon the conversion from a limited liability company to a corporation on January 23, 2014, the Company established a $132 million provision for deferred income taxes, which was recognized as tax expense from continuing operations.  The primary upward adjustments in the effective tax rate above the U.S. statutory rate are the adjustment related to converting from a limited liability company to a corporation noted above along with non-deductible incentive unit compensation.

 

The following is an analysis of the Company’s consolidated income tax expense:

 

 

 

Three Months Ended March 31,

 

 

 

2014

 

2013

 

 

 

(In thousands)

 

Current

 

$

963

 

$

 

Deferred

 

134,250

 

 

 

 

 

 

 

 

Provision for Income Taxes

 

$

135,213

 

$

 

 

Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of enacted tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likely of being realized upon ultimate settlement

 

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with a taxing authority that has full knowledge of all relevant information. The Company’s policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At March 31, 2014, the Company did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.

 

The Company’s U.S. federal income tax returns and Texas franchise tax returns for 2010 and beyond remain subject to examination by the taxing authorities. There are no material unresolved items related to periods previously audited by these taxing authorities. No other jurisdiction’s returns are significant to the Company’s financial position.

 

New Accounting Pronouncements

 

The Company has reviewed recently issued accounting standards and plans to adopt those that are applicable to it.  It does not expect the adoption of those standards to have a material impact on its financial position, results of operations or cash flows.

 

NOTE 3—ACQUISITIONS AND SALES OF OIL AND NATURAL GAS PROPERTY INTERESTS

 

Pro Forma Results

 

The Company’s pro forma results for the three months ended March 31, 2013 were derived from the actual results of the Company’s accounting predecessor, which reflects the combined results of RSP LLC and Rising Star, and have been adjusted to reflect the Collins and Wallace Contributions and the ACTOIL NPI Repurchase, both of which were completed in connection with the IPO on January 23, 2014, as if such transactions had occurred on January 1, 2013. Additionally, the pro forma results for the three months ended March 31, 2013 include the estimated activity associated with the Spanish Trail Acquisition (as defined below), which was completed in September 2013, and the Resolute Sale, which was completed in March 2013, as if each of these transactions had occurred on January 1, 2013.

 

Our pro forma results for the three months ended March 31, 2014 were derived from our actual results and have been adjusted to reflect the Collins and Wallace Contributions and the ACTOIL NPI Repurchase, both of which were completed in connection with the IPO on January 23, 2014, as if such transactions had occurred on January 1, 2013.

 

The pro forma financial information included below does not give effect to certain acquisitions that were immaterial to our actual and pro forma results for the periods reflected below and does not make any adjustments for non-recurring expenses associated with the IPO.

 

The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

 

 

 

Three Months Ended March 31, 2014

 

Three Months Ended March 31, 2013

 

 

 

Actual

 

Pro Forma

 

Actual

 

Pro Forma

 

 

 

(In thousands)

 

(In thousands)

 

Contributions:

 

 

 

 

 

 

 

 

 

Revenues

 

$

57,758

 

$

62,744

 

$

24,655

 

$

34,100

 

Net income (loss)

 

$

(127,530

)

$

(127,301

)

$

12,866

 

$

16,519

 

 

Recent Acquisitions

 

During the first quarter of 2014, the Company acquired additional acreage prospective for horizontal development in Martin, Glasscock and Dawson counties for an aggregate purchase price of approximately $79 million in three separate transactions with approximately $69 million recorded as proved oil and natural gas properties. The transactions were financed with borrowings under the Company’s revolving credit facility.

 

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Collins and Wallace Contributions

 

Collins, Wallace LP and Collins & Wallace Holdings, LLC contributed to RSP Inc. certain working interests in the Permian Basin in which RSP LLC already had working interests. In exchange, (i) Collins received shares of RSP Inc.’s common stock and the right to receive approximately $1.6 million in cash, (ii) Wallace LP received shares of RSP Inc.’s common stock and the right to receive $0.6 million in cash, and (iii) Collins & Wallace Holdings, LLC received shares of RSP Inc.’s common stock. The Collins and Wallace Contributions occurred in connection with the IPO.

 

These contributed working interests consist of the following: (i) Collins’ non-operated working interest in substantially all of the oil and natural gas properties that RSP LLC owned prior to the Spanish Trail Acquisition; (ii) Wallace LP’s non-operated working interest in substantially all of the oil and natural gas properties that RSP LLC owned prior to the Spanish Trail Acquisition; and (iii) Collins & Wallace Holdings, LLC’s non-operated working interest in the Spanish Trail Assets (as defined below).

 

A summary of the consideration transferred and the fair value of assets and liabilities acquired in connection with the Collins and Wallace Contributions is as follows (in thousands):

 

Value of the 22,023,654 shares of the Company’s common stock issued in the Collins and Wallace Contributions

 

$

429,461

 

Cash paid in the Collins and Wallace Contributions

 

2,219

 

Total consideration for the assets contributed in the Collins and Wallace Contributions

 

$

431,680

 

 

 

 

 

Fair value of oil and natural gas properties

 

$

644,052

 

Asset retirement obligation

 

(1,063

)

Deferred tax liability*

 

(211,309

)

Total net assets acquired

 

$

431,680

 

 


*       Amount represents the estimated book to tax difference in oil and natural gas properties as of the acquisition date on a tax-effected basis of approximately 35%.

 

ACTOIL NPI Repurchase

 

In July 2011, RSP LLC sold to ACTOIL a 25% NPI in substantially all of its oil and natural gas properties taken as a whole.  In addition, RSP LLC sold to ACTOIL a 25% NPI in the oil and natural gas properties acquired by RSP LLC in the Spanish Trail Acquisition. In connection with the IPO, ACTOIL contributed both 25% NPIs to the Company in exchange for shares of RSP Inc.’s common stock. The 25% NPIs exchanged for shares in the Company had a value of approximately $210.9 million and were accounted for as asset acquisitions.

 

The Company’s predecessor’s sale of properties to Resolute Natural Resources Southwest LLC (“Resolute”) in December 2012 and March 2013 resulted in ACTOIL earning cash proceeds through its NPI in the properties sold.  ACTOIL reduced its NPI account cumulative deficit balance with these proceeds, rather than receiving a cash distribution.  As such, the Company’s predecessor applied the NPI proceeds dollar-for-dollar to reduce the NPI deficit balance and recorded the amount as a long-term NPI payable on its balance sheet.  This amount was eliminated upon ACTOIL contributing its NPI in exchange for common shares.

 

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A summary of the consideration transferred and the assets acquired and liabilities acquired in connection with the ACTOIL NPI Repurchase is as follows (in thousands):

 

Value of the 10,816,626 shares of the Company’s common stock issued in the ACTOIL NPI Repurchase

 

$

210,924

 

Elimination of NPI payable

 

(36,931

)

Total consideration for the assets contributed in the ACTOIL NPI Repurchase

 

$

173,993

 

 

 

 

 

Oil and natural gas properties cost

 

$

158,115

 

Asset retirement obligation

 

(639

)

Deferred tax asset*

 

16,517

 

Total net assets acquired

 

$

173,993

 

 


*       Amount represents the estimated book to tax difference in oil and natural gas properties as of the acquisition date on a tax-effected basis of approximately 35%.

 

Spanish Trail Acquisition

 

On September 10, 2013, RSP LLC acquired additional working interests in certain of its existing properties in the Permian Basin (the “Spanish Trail Acquisition”) from Summit Petroleum, LLC (“Summit”) and EGL Resources, Inc. (“EGL”).  The aggregate purchase price for the assets to be acquired in the Spanish Trail Acquisition (the “Spanish Trail Assets”) agreed to by RSP LLC and the sellers was $155 million.

 

Subsequent to the signing of the purchase agreement and prior to the closing of the Spanish Trail Acquisition, Collins and Wallace LP, non-operating working interest owners in the Spanish Trail Assets, exercised preferential purchase rights granted under a joint operating agreement among the working interest owners in the Spanish Trail Assets. The preferential purchase rights gave Collins and Wallace LP the right to purchase a portion of the working interests sold by Summit and EGL. Collins and Wallace LP completed this acquisition through Collins & Wallace Holdings, LLC, a newly formed entity that is jointly owned by Collins and Wallace LP, which contributed these acquired assets to RSP Inc. in exchange for shares of RSP Inc.’s common stock in connection with the IPO. The exercise of the preferential purchase rights reduced RSP LLC’s purchase price from $155 million to $121 million.

 

Simultaneously with the closing of the Spanish Trail Acquisition, pursuant to ACTOIL’s exercise of a right of first refusal granted by RSP LLC in the agreement that governs ACTOIL’s NPI investment, RSP LLC conveyed a 25% NPI in the Spanish Trail Asses taken as a whole, excluding the portion acquired by Collins & Wallace Holdings, LLC, to ACTOIL in exchange for cash equal to 25% of RSP LLC’s $121 million purchase price.

 

RSP LLC allocated the net purchase price to the oil and natural gas properties acquired and asset retirement obligation assumed as follows (in thousands):

 

Net purchase price

 

$

120,521

 

25% NPI Sale to ACTOIL

 

(30,131

)

Oil and natural gas properties acquired

 

$

90,390

 

Asset retirement obligation assumed

 

296

 

Oil and natural gas properties

 

$

90,686

 

 

The Spanish Trail Acquisition was funded with a $70 million term loan, borrowings under the Company’s revolving credit facility (described below in Note 6) and the issuance of the NPI to ACTOIL described above.

 

Resolute Sale

 

Effective October 1, 2012, RSP LLC, ACTOIL and other minority non-operating working interest owners entered into a Purchase, Sale, and Option Agreement (“PSA”) to sell an undivided 32.35% interest in certain assets for an aggregate purchase price of $110 million to Resolute (the “Resolute Sale”). The Company’s share of the

 

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purchase price was $69 million and was recorded as a reduction to the basis of the underlying oil and natural gas properties. To the extent that the proceeds received exceeded the cost basis of the oil and natural gas properties, the Company recorded a gain on the sale. In addition, RSP LLC and the other sellers sold Resolute an option (the “Option”) for $5 million, $2.4 million of which was the Company’s share. The Option allowed Resolute to acquire the remaining 67.65% interest in these certain assets. The Option was non-refundable and only entitled Resolute to a limited time period during which it could exercise the right to acquire the remaining interest in these certain assets, and therefore the Option fee was included in the consideration transferred in computing the gain on disposition of the assets described above. The Company recorded a gain in connection with the sale of the 32.35% interest in these assets and Option fee in the amount of $6.7 million for the year ended December 31, 2012.

 

In March 2013, Resolute exercised the right to acquire the 67.65% remaining interest in these assets from RSP LLC, ACTOIL and other working interest owners for an additional purchase price of approximately $230 million. RSP LLC’s share of the purchase price was $144.2 million. In connection with the transaction closing in March 2013, RSP LLC recorded a gain of approximately $6 million.

 

The PSA contained customary closing conditions and included a $5 million title and environmental escrow (net to RSP LLC) and an $11 million indemnity escrow (net to RSP LLC) which were held back from the initial purchase price to provide for these contingencies. Amounts held in escrow for potential indemnity matters were not initially considered in the computation of the gain in connection with the sale of these certain assets because the Company could not reasonably estimate the potential outcome of any such matters at the time of the initial closing of the transaction.

 

Subsequent to the initial closing, in October 2013, RSP LLC received the first two scheduled escrow payments under the terms of the PSA totaling approximately $12 million. The receipt of these funds substantially resolved any uncertainty associated with the ability to collect the remaining portion of the amounts held in escrow, and therefore, the Company recorded the gain associated with all funds received and the remaining escrow amounts not yet received as collectability of such amounts was deemed probable. For the twelve months ended December 31, 2013, the total gain recognized on the Resolute Sale was approximately $22.7 million.

 

NOTE 4—DERIVATIVE INSTRUMENTS

 

Commodity Derivative Instruments

 

The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price risk inherent in its crude oil and natural gas production. These include over-the-counter (“OTC”) swaps, put options and collars. The derivative instruments are recorded at fair value on the consolidated balance sheets and any gains and losses are recognized in current period earnings.

 

Each swap transaction has an established fixed price. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.

 

Each put transaction has an established floor price. The Company pays the counterparty a premium in order to enter into the put transaction. When the settlement price is below the floor price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires.  All put options have expired as of December 31, 2013.

 

Each collar transaction has an established price floor and ceiling. When the settlement price is below the price floor established by these collars, the Company receives an amount from its counterparty equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume.

 

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Table of Contents

 

The following table summarizes all open positions as of March 31, 2014:

 

 

 

Year
2014

 

Year
2015

 

Crude Oil Swaps:

 

 

 

 

 

Notional volume (Bbl)

 

180,000

 

120,000

 

Weighted average price ($/Bbl)(1)

 

$

94.50

 

$

92.60

 

Crude Oil Collars:

 

 

 

 

 

Notional volume (Bbl)

 

1,149,000

 

492,000

 

Weighted average floor price ($/Bbl)(1)

 

$

86.29

 

$

85.49

 

Weighted average ceiling price ($/Bbl)(1)

 

$

100.35

 

$

94.14

 

Natural Gas Collars:

 

 

 

 

 

Notional volume (Mmbtu)

 

1,350,000

 

 

Weighted average floor price ($/Mmbtu)(2)

 

4.00

 

 

Weighted average ceiling price ($/Mmbtu)(2)

 

4.78

 

 

 


(1)         The crude oil derivative contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude.

(2)         The natural gas derivative contracts are settled based on the NYMEX Henry Hub closing settlement price.

 

Fair Values and Gains (Losses)

 

The following table presents the fair value of derivative instruments. The Company’s derivatives are presented as separate line items in its consolidated balance sheets as current and noncurrent derivative instrument assets and liabilities.  The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of the Company’s master netting arrangements.

 

 

 

Assets

 

Liabilities

 

 

 

March 31, 2014

 

December 31, 2013

 

March 31, 2014

 

December 31, 2013

 

 

 

(In thousands)

 

Derivative Instruments:

 

 

 

 

 

 

 

 

 

Current amounts

 

 

 

 

 

 

 

 

 

Commodity contracts

 

$

225

 

$

671

 

$

(4,156

)

$

(1,562

)

Noncurrent amounts

 

 

 

 

 

 

 

 

 

Commodity contracts

 

440

 

1,078

 

(207

)

(43

)

 

 

 

 

 

 

 

 

 

 

Total derivative instruments

 

$

665

 

$

1,749

 

$

(4,363

)

$

(1,605

)

 

Gains and losses on derivatives are reported in the consolidated statements of operations.

 

The following represents the Company’s reported gains and losses on derivative instruments for the periods presented:

 

 

 

Three Months Ended March 31,

 

 

 

2014

 

2013

 

 

 

(In thousands)

 

Loss on derivative instruments:

 

 

 

 

 

Commodity derivative instruments

 

$

(4,153

)

$

(1,653

)

Interest rate derivative instruments

 

 

(4

)

Total

 

$

(4,153

)

$

(1,657

)

 

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Offsetting of Derivative Assets and Liabilities

 

The following table presents the Company’s gross and net derivative assets and liabilities.

 

 

 

Gross Amount
Presented on
Balance Sheet

 

Netting
Adjustments(a)

 

Net
Amount

 

 

 

(In thousands)

 

March 31, 2014

 

 

 

 

 

 

 

Derivative instrument assets with right of offset or master netting agreements

 

$

665

 

$

(507

)

$

158

 

Derivative instrument liabilities with right of offset or master netting agreements

 

$

(4,363

)

$

507

 

$

(3,856

)

 

 

 

 

 

 

 

 

December 31, 2013

 

 

 

 

 

 

 

Derivative instrument assets with right of offset or master netting agreements

 

$

1,749

 

$

(1,332

)

$

417

 

Derivative instrument liabilities with right of offset or master netting agreements

 

$

(1,605

)

$

1,332

 

$

(273

)

 


(a)         With all of the Company’s financial trading counterparties, the Company has agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.

 

Credit-Risk Related Contingent Features in Derivatives

 

None of the Company’s derivative instruments contains credit-risk related contingent features. No amounts of collateral were posted by the Company related to net positions as of March 31, 2014 and December 31, 2013.

 

NOTE 5—FAIR VALUE MEASUREMENTS

 

The book values of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments.  The book value of the Company’s credit facilities approximate fair value as the interest rates are variable.  The fair value of derivative financial instruments is determined utilizing industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors.

 

The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

 

Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:

 

·                  Level 1—Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

·                  Level 2—Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.

 

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·                  Level 3—Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs that are not corroborated by market data. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

 

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

 

Fair Value Measurement on a Recurring Basis

 

The following table presents, by level within the fair value hierarchy, the Company’s assets and liabilities that are measured at fair value on a recurring basis.

 

 

 

Level 1

 

Level 2

 

Level 3

 

Total fair value

 

 

 

(In thousands)

 

As of March 31, 2014:

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

$

 

$

(3,698

)

$

 

$

(3,698

)

Total

 

$

 

$

(3,698

)

$

 

$

(3,698

)

 

 

 

Level 1

 

Level 2

 

Level 3

 

Total fair value

 

 

 

(In thousands)

 

As of December 31, 2013:

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

$

 

$

144

 

$

 

$

144

 

Total

 

$

 

$

144

 

$

 

$

144

 

 

Significant Level 2 assumptions used to measure the fair value of the commodity derivative instruments include current market and contractual commodity prices, implied volatility factors, appropriate risk adjusted discount rates, as well as other relevant data.

 

Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. There were no transfers between Level 1, Level 2 or Level 3 during the three months ended March 31, 2014 and the year ended December 31, 2013.

 

Nonfinancial Assets and Liabilities

 

Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. Additionally, fair value is used to determine the inception value of the Company’s AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Company’s AROs represent a nonrecurring Level 3 measurement.

 

The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement.

 

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NOTE 6—CREDIT AGREEMENT

 

On September 10, 2013, in conjunction with the Spanish Trail Acquisition, the Company amended and restated its credit agreement, dated December 15, 2010, with Comerica Bank, as administrative agent, and expanded its syndicated bank group to 11 lenders.  In addition, the Company entered into a new term loan in the amount of $70 million to partially finance the Spanish Trail Acquisition.

 

The Company’s revolving credit facility requires it to maintain the following three financial ratios:

 

·                  a working capital ratio, which is the ratio of consolidated current assets (includes unused commitments under its revolving credit facility and excludes restricted cash and derivative assets) to consolidated current liabilities (excluding the current portion of long-term debt under the credit facility and derivative liabilities), of not less than 1.0 to 1.0;

·                  a minimum interest coverage ratio, which is the ratio of consolidated EBITDAX (as defined in the credit agreement) to consolidated interest expense, of not less than 3.0 to 1.0; and

·                  a leverage ratio, which is the ratio of the sum of all of the Company’s debt to the consolidated EBITDAX (as defined in the credit agreement) for the four fiscal quarters then ended, of not greater than 4.0 to 1.0.

 

The Company’s revolving credit facility contains restrictive covenants that may limit its ability to, among other things, incur additional indebtedness, make loans to others, make investments, enter into mergers, make or declare dividends, enter into commodity hedges exceeding a specified percentage or its expected production, enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness, incur liens, sell assets or engage in certain other transactions without the prior consent of the lenders.

 

The Company was in compliance with such covenants and ratios as of March 31, 2014.

 

Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. RSP LLC has a choice of borrowing in Eurodollars or at the adjusted base rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted LIBOR rate (equal to the quotient of: (i) the LIBOR Rate divided by (ii) a percentage equal to 100% minus the maximum rate on such date at which the Administrative Agent is required to maintain reserves on “Eurocurrency Liabilities” as defined in and pursuant to Regulation D of the Board of Governors of the Federal Reserve System) plus an applicable margin ranging from 125 to 200 basis points, depending on the percentage of its borrowing base utilized. Adjusted base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s reference rate; (ii) the federal funds effective rate plus 100 basis points; and (iii) the adjusted LIBOR rate plus 100 basis points, plus an applicable margin ranging from 25 to 100 basis points, depending on the percentage of its borrowing base utilized, plus a facility fee of 0.50% charged on the borrowing base amount. At March 31, 2014, the variable rate of interest under the Company’s revolving credit facility was 1.73%. The Company may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs. As of March 31, 2014, the revolving credit facility has a margin of 1.25% to 2.00% plus LIBOR, plus a facility fee of 0.50% charged on the borrowing base amount.

 

The amount available to be borrowed under the revolving credit facility is subject to a borrowing base that is re-determined semiannually each May and November and depends on the volumes of proved oil and natural gas reserves and estimated cash flows from these reserves and commodity hedge positions. The borrowing base under the Company’s amended and restated credit agreement is $300 million as of March 31, 2014, with lender commitments of $500 million.

 

The maturity date of the Company’s revolving credit facility is September 10, 2017.

 

On January 23, 2014, the Company repaid the term loan in full, and as of March 31, 2014, the Company had no contractual obligations with respect to the term loan.

 

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Table of Contents

 

NOTE 7—COMMITMENTS AND CONTINGENCIES

 

Legal Matters

 

In the ordinary course of business, the Company may at times be subject to claims and legal actions. Management believes it is remote that the impact of such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

 

Environmental Matters

 

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed as incurred. The Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.

 

The Company accounts for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed.

 

Liabilities are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At March 31, 2014 and December 31, 2013, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

 

Leases

 

During 2011, RSP LLC entered into a month-to-month operating lease agreement and a long-term operating lease agreement for office space.  During February 2014, the Company entered into a 64-month lease agreement through May 2019 for office space.  Rent expense for the three months ended March 31, 2014 and 2013 was $82 thousand and $62 thousand.

 

NOTE 8—EQUITY-BASED COMPENSATION

 

Restricted Stock Awards

 

In connection with the IPO, the Company adopted the RSP Permian, Inc. 2014 Long Term Incentive Plan (the “LTIP”) for the employees, consultants and directors of the Company and its affiliates who perform services for the Company.  Refer to “Part III, Item 11. Executive Compensation” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 for additional information related to these equity-based compensation plans.

 

Share-based compensation expense for restricted stock awards issued to both employees and non-employee directors, which was recorded in “General and administrative expenses” in the accompanying consolidated statements of operations, was $0.8 million for the three months ended March 31, 2014.  The Company views restricted stock awards with graded vesting as single awards with an expected life equal to the average expected life and amortize the awards on a straight-line basis over the life of the awards.

 

The compensation expense for these awards was determined based on the market price of the Company’s common stock at the date of grant applied to the total number of shares that were anticipated to fully vest. As of March 31, 2014, the Company had unrecognized compensation expense of $8.9 million related to restricted stock awards which is expected to be recognized over a weighted average period of 2.2 years.

 

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Table of Contents

 

The following table represents restricted stock award activity for the three months ended March 31, 2014:

 

 

 

Shares

 

Wtd. Avg. Grant Price

 

Restricted shares outstanding, beginning of period

 

 

$

 

Restricted shares granted

 

421,999

 

23.05

 

Restricted shares outstanding, end of period

 

421,999

 

$

23.05

 

 

Incentive Units

 

Pursuant to the LLC Agreement of RSP LLC, certain incentive units are available to be issued to the Company’s management and employees, consisting of Tier I, Tier I A, Tier II, Tier III and Tier IV units. The incentive units are intended to be compensation for services rendered to the Company. All incentive units, whether vested or not, are forfeited if payouts are not achieved by a specified date. Tier I and Tier I A incentive units vest ratably over three years but are subject to forfeiture if payout is not achieved. Tier I and Tier I A payout is realized upon the return of members’ invested capital and a specified rate of return. Tiers II, III and IV incentive units vest only upon the achievement of certain distribution thresholds for each such Tier and each Tier of the incentive units is subject to forfeiture if the applicable required payouts are not achieved.  In addition, vested and unvested units will be forfeited if an incentive unit holder’s employment is terminated for cause or if the unitholder voluntarily terminates his or her employment.

 

In connection with the IPO, the incentive units of RSP LLC became incentive units in RSP Permian Holdco, L.L.C. and therefore based upon distributions to members of RSP Permian Holdco, L.L.C. rather than members of RSP LLC.  The terms and conditions of the profits interest awards remained substantially similar to the terms applicable to the incentive unit awards prior to the IPO, including the retention of existing vesting schedules.  See “Part III, Item 11. Executive Compensation” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 for additional information regarding the incentive units.

 

The achievement of payout conditions is a performance condition that requires the Company to assess, at each reporting period, the probability that an event of payout will occur. Compensation cost is required to be recognized at such time that the payout terms are probable of being met. At the grant dates and subsequent reporting periods, the Company did not deem as probable that such payouts would be achieved for any Tier of incentive units.

 

At such time that the occurrence of the performance conditions associated with these incentive units are deemed probable, the Company will record a non-cash compensation expense based upon the grant date fair value of the incentive units that are probable of reaching payout as a result of reaching established distribution thresholds. As of December 31, 2013, the unrecognized non-cash compensation expense associated with all tiers of the incentive units was approximately $16.3 million. After successful completion of the IPO, the performance conditions associated with the Tier I, Tier I A and Tier II incentive units were deemed probable of reaching payout, which resulted in the recognition of non-cash compensation expense of approximately $11.1 million. The Tier I A and Tier II incentive units will have a remaining unrecognized non-cash compensation expense of approximately $1.6 million which will be amortized over the remaining service period and result in a $0.7 million non-cash compensation expense in the remainder of 2014 and $0.9 million in 2015. The remaining unrecognized non-cash compensation expense related to the Tier III and Tier IV incentive units is approximately $3.5 million and will be recognized when it is deemed that the Tier III and Tier IV incentive units are probable of reaching payout as a result of reaching the established distribution thresholds.

 

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Table of Contents

 

NOTE 9—EARNINGS PER SHARE & PRO FORMA EARNINGS PER SHARE

 

Earnings per Share

 

The Company’s basic earnings per share amounts have been computed using the two-class method based on the weighted-average number of shares of common stock outstanding for the period.  Because the Company recognized a net loss for the first quarter of 2014, unvested restricted share awards were not recognized in dilutive earnings per share calculations as they would be antidilutive.  A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:

 

 

 

Three Months Ended
March 31, 2014

 

 

 

(In thousands)

 

Numerator:

 

 

 

Net loss available to stockholders

 

$

(127,530

)

Basic net loss allocable to participating securities (1)

 

 

Loss available to stockholders

 

$

(127,530

)

 

 

 

 

Denominator:

 

 

 

Weighted average number of common shares outstanding - basic

 

62,904

 

Effect of dilutive securities:

 

 

 

Restricted stock

 

 

Weighted average number of common shares outstanding - diluted

 

62,904

 

 

 

 

 

Net loss per share:

 

 

 

Basic

 

$

(2.03

)

Diluted

 

$

(2.03

)

 


(1)    Restricted share awards that contain non-forfeitable rights to dividends are participating securities and, therefore, are included in computing earnings using the two-class method. Participating securities, however, do not participate in undistributed net losses.

 

Pro Forma Earnings per Share

 

The Company computed a pro forma income tax provision as if the Company was subject to income taxes since January 1, 2014. The pro forma tax provision has been calculated at a rate based upon a federal corporate level tax rate and a state tax rate, net of federal benefit, and excludes the non-recurring tax adjustment related to the conversion of the Company from an LLC to a corporation on January 23, 2014, as further described in Note 2 under “Income Taxes.”

 

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Table of Contents

 

The Company’s pro forma basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period, as if the common shares issued in the IPO were outstanding for the entire year. A reconciliation of the components of pro forma basic and diluted earnings per common share is presented in the table below:

 

 

 

Three Months Ended
March 31, 2014

 

Numerator:

 

 

 

Income before taxes, as reported

 

$

7,683

 

Pro forma provision for income taxes

 

2,689

 

Pro forma net income available to stockholders

 

4,994

 

Basic net income allocable to participating securities

 

29

 

Pro forma net income available to stockholders

 

$

4,956

 

 

 

 

 

Denominator:

 

 

 

Weighted average number of common shares outstanding - basic

 

72,500

 

Effect of dilutive securities:

 

 

 

Restricted stock

 

 

Weighted average number of common shares outstanding - diluted

 

72,500

 

 

 

 

 

Net income per share:

 

 

 

Basic

 

$

0.07

 

Diluted

 

$

0.07

 

 

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Table of Contents

 

Item 2.                                 Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes in “Part I, Item 1. Financial Statements.”  The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions and resources. Please see “Cautionary Note Regarding Forward-Looking Information” elsewhere in this Quarterly Report on Form 10-Q and “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013.

 

Our Predecessor and RSP Permian, Inc.

 

RSP Permian, Inc. was formed in September 2013 and does not have historical financial operating results. For purposes of this Quarterly Report on Form 10-Q, our accounting predecessor reflects the combined results of RSP LLC and Rising Star.

 

RSP LLC was formed in 2010 to engage in the acquisition, development, exploration and exploitation of oil and natural gas reserves in the Permian Basin. In connection with the IPO, pursuant to the terms of a corporate reorganization, RSP LLC became a wholly owned subsidiary of RSP Inc. See “— The IPO and Related Transactions—Corporate Reorganization” for more information. Also in connection with the IPO, Rising Star contributed to RSP Inc. certain assets that represent substantially all of Rising Star’s production and revenues for each of the years ended December 31, 2013 and 2012 in exchange for shares of RSP Inc.’s common stock and cash. See “— The IPO and Related Transactions—The Rising Star Acquisition” for more information.

 

The IPO and Related Transactions

 

In January 2014, we successfully completed the IPO, selling 23 million shares at $19.50 per share and raising $449 million in gross proceeds. Of the 23 million shares, 9.2 million were shares sold by RSP Inc., resulting in approximately $163 million of net proceeds. We did not receive any proceeds from the sale of shares by selling stockholders. In connection with the IPO, we completed the transactions described below.

 

Corporate Reorganization.  Pursuant to the terms of a corporate reorganization, (i) the members of RSP LLC contributed all of their interests in RSP LLC to RSP Permian Holdco, L.L.C., a newly formed entity that is wholly owned by such members, and (ii) RSP Permian Holdco, L.L.C. contributed all of its interests in RSP LLC to RSP Inc. in exchange for shares of common stock of RSP Inc., an assignment of RSP LLC’s pro rata share of an escrow related to the Resolute Sale (which escrow is described in Note 3 to the consolidated financial statements) and the right to receive approximately $27.7 million in cash. As a result of the reorganization, RSP LLC became a wholly owned subsidiary of RSP Inc.

 

The Rising Star Acquisition. We acquired from Rising Star working interests in certain acreage and wells in the Permian Basin in which RSP LLC already had working interests in exchange for shares of RSP Inc. common stock and the right to receive approximately $1.7 million in cash.

 

The Collins and Wallace Contributions. Collins, Wallace LP and Collins & Wallace Holdings, LLC, a newly formed entity that is owned equally by Collins and Wallace LP, contributed to RSP Inc. certain working interests in the Permian Basin in which RSP LLC already had working interests. In exchange, (i) Collins received shares of RSP Inc.’s common stock and the right to receive approximately $1.6 million in cash, (ii) Wallace LP received shares of RSP Inc.’s common stock and the right to receive $0.6 million in cash and (iii) Collins & Wallace Holdings, LLC received shares of RSP Inc.’s common stock.

 

The Pecos Contribution. Pecos, an entity owned by certain members of our management team, contributed to RSP Inc. certain working interests in certain acreage and wells in the Permian Basin in which RSP LLC. already has working interests (the “Pecos Contribution”). In exchange, Pecos received shares of RSP Permian, Inc.’s common stock.

 

The ACTOIL NPI Repurchase. In July 2011, RSP LLC sold to ACTOIL a 25% NPI in substantially all of its oil and natural gas properties taken as a whole, and in September 2013, RSP LLC sold to ACTOIL a 25% NPI in the

 

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Table of Contents

 

Spanish Trail Assets acquired by RSP LLC.  ACTOIL contributed both 25% NPIs to RSP Inc. in exchange for shares of RSP Inc.’s common stock.

 

Recent Acquisitions

 

During the first quarter of 2014, the Company acquired additional acreage prospective for horizontal development located in Martin, Glasscock and Dawson counties in Texas for an aggregate purchase price of approximately $79 million in three separate transactions, which are described below in more detail, with approximately $69 million recorded as proved oil and natural gas properties. These transactions were financed with borrowings under the Company’s revolving credit facility.

 

In Martin County, the Company acquired a 17.5% non-operated working interest in producing properties located between the Company’s operated leasehold positions. The properties include 6,451 gross (1,125 net) acres, and net production, on a two-stream basis, averaged approximately 500 Boe per day (76% oil) for the month of February 2014 from 147 vertical wells. The operator of these properties has indicated it has identified 196 horizontal drilling locations in six target intervals, including the Middle Spraberry, Lower Spraberry, Wolfcamp A, Wolfcamp B, Wolfcamp D (Cline) and Clearfork formations.

 

In Glasscock County, the Company acquired a 100% operated working interest in 961 acres of undeveloped leasehold. The Company has identified 30 horizontal locations on these properties in the Middle Spraberry, Lower Spraberry, Wolfcamp A, Wolfcamp B and Wolfcamp D (Cline) formations.

 

In Dawson County, the Company also acquired an additional 3,766 gross (3,230 net) undeveloped acres in the area where RSP LLC acquired leasehold interests in October 2013, bringing the Company’s total acreage in Dawson County to 13,230 gross (11,345 net) acres. The Company has identified approximately 61 additional net horizontal locations in the Middle Spraberry, Lower Spraberry and Wolfcamp A/B formations.

 

Pro Forma Quarterly Financial Data

 

The financial information provided in the Company’s financial statements includes 22 days of the Company’s predecessor financial information plus the Company’s activities for the rest of the quarter.

 

The below pro forma information for the three months ended December 31, 2013 was derived from the actual results of the Company’s predecessor, which reflects the combined results of RSP LLC and Rising Star, and the below pro forma information for the three months ended March 31, 2014 was derived from our actual results.  The below pro forma information has been adjusted to reflect the Collins and Wallace Contributions and the ACTOIL NPI Repurchase, both of which were completed in connection with the IPO on January 23, 2014, as if such transactions had occurred on January 1, 2013.  The below pro forma information also reflects adjustments for non-recurring expenses associated with the IPO.

 

The pro forma financial information included below does not give effect to certain acquisitions that were immaterial to our actual and pro forma results for the periods reflected below.

 

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Table of Contents

 

 

 

RSP Permian, Inc.

 

RSP Permian, Inc.
Pro Forma

 

 

 

Three Months Ended

 

Three Months Ended

 

 

 

March 31, 2014

 

December 31, 2013

 

March 31, 2014

 

December 31, 2013

 

Production data:

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

544

 

347

 

594

 

516

 

Natural gas (MMcf)

 

573

 

403

 

621

 

574

 

NGLs (MBbls)

 

133

 

69

 

143

 

109

 

Total (MBoe)

 

772

 

483

 

841

 

721

 

Average net daily production (Boe/d)

 

8,578

 

5,250

 

9,339

 

7,837

 

Average prices before effects of hedges(1)(2):

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

$

94.60

 

$

94.64

 

$

94.21

 

$

94.38

 

Natural gas (per Mcf)

 

3.85

 

3.53

 

3.86

 

3.38

 

NGLs (per Bbl)

 

30.79

 

30.68

 

30.82

 

28.94

 

Total (per Boe)

 

$

74.82

 

$

75.32

 

$

74.65

 

$

74.64

 

Average realized prices after effects of hedges(1)(2):

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

$

93.91

 

$

95.44

 

$

93.57

 

$

94.91

 

Natural gas (per Mcf)

 

3.85

 

3.53

 

3.86

 

3.38

 

NGLs (per Bbl)

 

30.79

 

30.68

 

30.82

 

28.94

 

Total (per Boe)

 

$

75.22

 

$

75.89

 

$

74.19

 

$

75.02

 

Average costs (per Boe):

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

9.15

 

$

8.53

 

$

9.23

 

$

8.74

 

Production and ad valorem taxes

 

5.02

 

4.98

 

4.91

 

6.31

 

Depreciation, depletion and amortization

 

21.19

 

12.52

 

23.79

 

17.96

 

General and  administrative expenses(3) 

 

22.04

 

2.44

 

2.46

 

1.60

 

 


(1)         Average prices shown in the table reflect prices both before and after the effects of our cash payments/receipts on our commodity derivative transactions. Our calculation of such effects includes realized gains or losses on cash settlements for commodity derivative transactions and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments settled in the period.

(2)         Average realized prices for oil are net of transportation costs. Average realized prices for natural gas do not include transportation costs; instead, transportation costs related to our gas production and sales are included in our lease operating expenses. No transportation costs are associated with NGL production and sales.

(3)         Pro forma general and administrative expenses do not include additional expenses we would have incurred as a result of being a public company for the entire period presented.  In addition, non-recurring general and administrative expenses associated with non-cash compensation expense were excluded from the pro forma general and administrative expenses.

 

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Table of Contents

 

Statement of Operations

(Unaudited)

 

 

 

RSP Permian, Inc.

 

RSP Permian, Inc.
Pro Forma

 

 

 

Three Months Ended

 

Three Months Ended

 

 

 

March 31, 2014

 

December 31, 2013

 

March 31, 2014

 

December 31, 2013

 

 

 

(In thousands)

 

Revenues:

 

 

 

 

 

 

 

 

 

Oil sales

 

$

51,471

 

$

32,842

 

$

55,930

 

$

48,733

 

Natural gas sales

 

2,206

 

1,421

 

2,397

 

1,937

 

NGL sales

 

4,081

 

2,117

 

4,417

 

3,145

 

Total revenues

 

$

57,758

 

$

36,380

 

$

62,744

 

$

53,815

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

7,063

 

$

4,120

 

$

7,757

 

$

6,298

 

Production and ad valorem taxes

 

3,876

 

2,403

 

4,127

 

4,546

 

Depreciation, depletion and amortization

 

16,361

 

6,045

 

19,994

 

12,940

 

Asset retirement obligation accretion

 

29

 

38

 

38

 

53

 

Exploration

 

756

 

74

 

756

 

74

 

General and administrative expenses

 

17,016

 

1,180

 

2,064

 

1,157

 

Total operating expenses

 

45,101

 

13,860

 

34,736

 

25,068

 

Operating income

 

$

12,657

 

$

22,520

 

$

28,008

 

$

28,747

 

 

 

 

 

 

 

 

 

 

 

Other income (expense):

 

 

 

 

 

 

 

 

 

Other income

 

$

310

 

$

338

 

$

309

 

$

339

 

Gain (loss) on derivative instruments

 

(4,153

)

758

 

(4,153

)

758

 

Interest expense

 

(1,131

)

(3,446

)

(1,131

)

(4,865

)

Total other income (expense)

 

$

(4,974

)

$

(2,350

)

$

(4,975

)

$

(3,768

)

Income before taxes

 

7,683

 

20,170

 

23,033

 

24,979

 

Income tax (expense) benefit

 

(135,213

)

(2,194

)

(8,292

)

(8,992

)

Net income

 

$

(127,530

)

$

17,976

 

$

14,741

 

$

15,987

 

 

Overview

 

The Company’s financial and operating performance for the three months ended March 31, 2014 included the following highlights:

 

·                  Completed the IPO, issuing 23 million shares at $19.50 per share for gross proceeds of $449 million;

·                  Acquired $800 million of oil and gas properties in the Company’s core area through the Collins and Wallace Contributions, the ACTOIL NPI Repurchase, the Pecos Contribution and the acquisition from Rising Star;

·                  Acquired approximately $79 million of oil and gas properties in Martin, Glasscock and Dawson counties in Texas; and

·                  Added our fourth operated horizontal rig and our second operated vertical rig, tripling our total rig count compared to six months ago.

 

During the three months ended March 31, 2014, our average daily production was approximately 8,578 Boe/d, consisting of 6,045 Bbls/d of oil, 6,363 Mcf/d of natural gas and 1,472 Bbls/d of NGLs, an increase of 98%, or 4,245 Boe/d, from our average daily production of 4,333 Boe/d for the three months ended March 31, 2013, consisting of 2,878 Bbls/d of oil, 4,733 Mcf/d of natural gas and 667 Bbls/d of NGLs. This increase in our average

 

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net daily production was despite the Resolute Sale, pursuant to which we sold approximately 40% of our then-current production, which closed in part in December 2012 and in part in March 2013.

 

During the first quarter of 2014, the Company drilled 16 horizontal wells (seven operated) and completed ten horizontal wells (six operated). The Company is currently in the drilling or completion phase on ten operated horizontal wells in five different horizontal zones: one Middle Spraberry, four Lower Spraberry, one Wolfcamp A, three Wolfcamp B and one Wolfcamp D. The Company’s operated horizontal rigs are operating in Midland County (two rigs), Andrews County (one rig) and Dawson County (one rig). The Company’s two operated vertical rigs are both operating in Midland County. The Company expects to operate four horizontal rigs and two vertical rigs for the remainder of 2014.

 

How We Evaluate Our Operations

 

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

 

·                  production volumes;

·                  realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts on our production; and

·                  lease operating expenses.

 

Sources of Our Revenues

 

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas during processing. Our oil and natural gas revenues do not include the effects of derivatives. For the three months ended March 31, 2014 and 2013, our revenues were derived 89% from oil sales. Natural gas sales accounted for approximately 4% and 5% of total sales for the three months ended March 31, 2014 and 2013, respectively. Our revenues from NGL sales for the three months ended March 31, 2014 and 2013 were 7% and 6%, respectively. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

 

Production Volumes

 

The following table presents historical production volumes for the Company’s properties for the three months ended March 31, 2014 and 2013.

 

 

 

Three Months Ended March 31,

 

 

 

 

 

2014

 

2013

 

% Change

 

Oil (MBbls)

 

544

 

259

 

110

%

Natural gas (MMcf)

 

573

 

426

 

34

%

NGLs (MBbls)

 

133

 

60

 

120

%

Total (MBoe)

 

772

 

390

 

98

%

Average net daily production (Boe/d)

 

8,578

 

4,333

 

98

%

 

As reservoir pressures decline, production from a given well or formation decreases. Growth in our future production and reserves will depend on our ability to continue to add proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through increased drilling as well as acquisitions. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including our ability to borrow or raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions.

 

Realized Prices on the Sale of Oil, Natural Gas and NGLs

 

The NYMEX WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. For example, the prices we realize on the oil we produce are affected by the ability to transport crude oil to the Cushing, Oklahoma transport hub and the Gulf Coast refineries. Periodically, logistical

 

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and infrastructure constraints at the Cushing, Oklahoma transport hub have resulted in an oversupply of crude oil at Midland, Texas and thus lowered prices for Midland WTI. These lower prices adversely affected the prices we realized on oil sales and increased our differential to NYMEX WTI. However, several projects have recently been implemented and several more are underway, which have eased these transportation difficulties and which have reduced our differentials to NYMEX WTI to historical norms.

 

The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. For example, liquids-rich natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater quantity of NGLs. Location differentials to NYMEX Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant generally in the form of percentage of proceeds.

 

The following table provides the high and low prices for NYMEX WTI and NYMEX Henry Hub prompt month contract prices and our differential to the average of those benchmark prices for the periods indicated. The differential varies, but our oil and natural gas normally sell at a discount to the NYMEX WTI and NYMEX Henry Hub price, respectively.

 

 

 

Three Months Ended March 31,

 

 

 

2014

 

2013

 

Oil:

 

 

 

 

 

NYMEX WTI high

 

$

104.92

 

$

97.94

 

NYMEX WTI low

 

91.66

 

90.12

 

Average NYMEX WTI

 

98.61

 

94.41

 

Differential to average NYMEX WTI

 

(4.01

)

(9.76

)

Realized crude oil price

 

94.60

 

84.64

 

 

 

 

 

 

 

Natural Gas:

 

 

 

 

 

NYMEX Henry Hub high

 

$

6.15

 

$

4.07

 

NYMEX Henry Hub low

 

4.01

 

3.11

 

Average NYMEX Henry Hub

 

4.72

 

3.48

 

Differential to Average NYMEX Henry Hub

 

(0.87

)

(0.74

)

Realized natural gas price

 

3.85

 

2.73

 

 

 

 

 

 

 

NGLs:

 

 

 

 

 

NGL Realized Price as a % of Average NYMEX WTI

 

31

%

28

%

 

In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. For example, during the three months ended March 31, 2014, the NYMEX WTI prompt month oil price ranged from a high of $104.92 per Bbl to a low of $91.66 per Bbl, while the NYMEX Henry Hub prompt month natural gas price ranged from a high of $6.15 per MMBtu to a low of $4.01 per MMBtu.

 

Due to the inherent volatility in commodity prices, we have historically used commodity derivative instruments, such as collars, swaps and puts, to hedge price risk associated with a significant portion of our anticipated production. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in commodity prices and provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in commodity prices and may partially limit our potential gains from future increases in prices. None of our instruments are used for trading purposes. We do not speculate on commodity prices but rather attempt to hedge a portion of our physical production in order to protect our returns. Our revolving credit facility limits our ability to enter into commodity hedges covering greater than 85% of our reasonably anticipated projected production volume.

 

We will continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. We are not under an obligation to hedge a specific portion of our production.

 

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Our open positions as of March 31, 2014 were as follows:

 

Description & Production Period

 

Volume (Bbls)

 

Weighted
Average
Floor price
($/Bbl)(1)

 

Weighted
Average
Ceiling price
($/Bbl)(1)

 

Weighted
Average
Swap price
($/Bbl)(1)

 

Crude Oil Swaps:

 

 

 

 

 

 

 

 

 

April 2014 — December 2014

 

90,000

 

$

 

$

 

$

96.40

 

April 2014 — December 2015

 

210,000

 

 

 

92.60

 

 

 

 

 

 

 

 

 

 

 

Crude Oil Collars:

 

 

 

 

 

 

 

 

 

April 2014 — September 2014

 

6,000

 

$

85.00

 

$

113.04

 

$

 

April 2014 — December 2014

 

738,000

 

85.79

 

102.11

 

 

April 2014 — December 2015

 

525,000

 

85.00

 

95.00

 

 

January 2015 — December 2015

 

72,000

 

80.00

 

93.25

 

 

July 2014 — September 2014

 

90,000

 

90.00

 

101.50

 

 

October 2014 — December 2014

 

90,000

 

90.00

 

97.33

 

 

January 2015 — March 2015

 

120,000

 

90.00

 

92.53

 

 

 


(1)         The crude oil derivative contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude.

 

Description & Production Period

 

Volume
(MMBtu)

 

Weighted
Average
Floor price
($/MMBtu)(1)

 

Weighted
Average
Ceiling price
($/MMBtu)(1)

 

Weighted
Average
Swap price
($/MMBtu)(1)

 

Natural Gas Collars:

 

 

 

 

 

 

 

 

 

April 2014 — December 2014

 

1,350,000

 

$

4.00

 

$

4.78

 

$

 

 


(1)         The natural gas derivative contracts are settled based on the NYMEX closing settlement price.

 

Subsequent to March 31, 2014, we entered into the following oil and natural gas commodity hedges:

 

Description & Production Period

 

Volume (Bbls)

 

Weighted
Average
Floor price
($/Bbl)(1)

 

Weighted
Average
Ceiling price
($/Bbl)(1)

 

Weighted
Average
Swap price
($/Bbl)(1)

 

Crude Oil Collars:

 

 

 

 

 

 

 

 

 

January 2015 — December 2015

 

960,000

 

$

85.00

 

$

95.00

 

$

 

January 2015 — June 2015

 

240,000

 

90.00

 

96.00

 

 

 


(1)         The crude oil derivative contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude.

 

Factors Affecting the Comparability of Our Financial Condition and Results of Operations

 

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:

 

Recent and Formation Transactions

 

The historical results of operations through January 22, 2014 are based on the financial statements of our accounting predecessor, which reflects the combined results of RSP LLC and Rising Star, prior to the corporate reorganization and the transactions described above under “—The IPO and Related Transactions,” which increased the scope of our operations.

 

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Public Company Expenses

 

We incur direct, incremental general and administrative expenses as a result of being a publicly traded company, including, but not limited to, increased scope of our operations as a result of recent activities and costs associated with hiring new personnel, implementation of compensation programs that are competitive with our public company peer group, annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These direct, incremental general and administrative expenses are not included in our historical results of operations prior to the IPO.

 

Income Taxes

 

Our predecessor was not subject to federal income taxes and the tax liability with respect to our taxable income was passed through to our predecessor’s members. Accordingly, the financial data attributable to our predecessor contain no provision for federal income taxes. Our predecessor was subject to State of Texas franchise taxes at less than 1% of modified pre-tax earnings. We are taxed as a subchapter C corporation under the Internal Revenue Code of 1986, as amended, and subject to income taxes at a blended statutory rate of 35% of pre-tax earnings.

 

Increased Drilling Activity

 

Our board of directors has approved a capital budget for 2014 of $365 million. We expect that approximately 80% of our total drilling and completion expenditures in 2014 will be allocated to the drilling of horizontal wells. Our 2014 capital budget represents a 69% increase over our $216 million 2013 capital budget. The ultimate amount of capital that we expend may fluctuate materially based on market conditions and our drilling results.

 

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Results of Operations

 

Three Months Ended March 31, 2014 Compared to Three Months Ended March 31, 2013

 

Oil, Natural Gas and NGL Sales Revenues. The following table provides the components of our revenues for the periods indicated, as well as each period’s respective average prices and production volumes:

 

 

 

Three Months Ended
March 31,

 

 

 

 

 

 

 

2014

 

2013

 

Change

 

% Change

 

Revenues (in thousands, except percentages):

 

 

 

 

 

 

 

 

 

Oil sales

 

$

51,471

 

$

21,923

 

$

29,548

 

135

%

Natural gas sales

 

2,206

 

1,165

 

1,041

 

89

%

NGL sales

 

4,081

 

1,567

 

2,514

 

160

%

Total revenues

 

$

57,758

 

$

24,655

 

$

33,103

 

134

%

Average sales prices:

 

 

 

 

 

 

 

 

 

Oil (per Bbl) (excluding impact of cash settled derivatives)

 

$

94.60

 

$

84.64

 

$

9.96

 

12

%

Oil (per Bbl) (after impact of cash settled derivatives)

 

93.91

 

85.01

 

8.90

 

10

%

Natural gas (per Mcf)

 

3.85

 

2.73

 

1.12

 

41

%

NGLs (per Bbl)

 

30.79

 

26.12

 

4.67

 

18

%

Total (per Boe) (excluding impact of cash settled derivatives)

 

$

74.82

 

$

63.22

 

$

11.60

 

18

%

Total (per Boe) (after impact of cash settled derivatives)

 

$

74.32

 

$

63.46

 

$

12.24

 

19

%

Production:

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

544

 

259

 

285

 

110

%

Natural gas (MMcf)

 

573

 

426

 

147

 

34

%

NGLs (MBbls)

 

133

 

60

 

73

 

120

%

Total (MBoe)

 

772

 

390

 

382

 

98

%

Average daily production volume:

 

 

 

 

 

 

 

 

 

Oil (Bbls/d)

 

6,045

 

2,878

 

3,167

 

110

%

Natural gas (Mcf/d)

 

6,363

 

4,733

 

1,630

 

34

%

NGLs (Bbls/d)

 

1,472

 

667

 

805

 

120

%

Total (Boe/d)

 

8,578

 

4,333

 

4,245

 

98

%

 

The following table shows the relationship between our average realized oil price as a percentage of the average NYMEX price and the relationship between our average realized natural gas price as a percentage of the average NYMEX price for the periods indicated. Management uses the realized price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.

 

 

 

Three Months Ended March 31,

 

 

 

2014

 

2013

 

Average realized oil price ($/Bbl)

 

$

94.60

 

$

84.64

 

Average NYMEX ($/Bbl)

 

98.61

 

94.41

 

Differential to NYMEX

 

(4.01

)

(9.76

)

Average realized oil price to NYMEX percentage

 

96

%

90

%

 

 

 

 

 

 

Average realized natural gas price ($/Mcf)

 

$

3.85

 

$

2.73

 

Average NYMEX ($/Mcf)

 

4.72

 

3.48

 

Differential to NYMEX

 

(0.87

)

(0.74

)

Average realized natural gas price to NYMEX percentage

 

82

%

79

%

 

 

 

 

 

 

Average realized NGL price ($/Bbl)

 

$

30.79

 

$

26.12

 

Average NYMEX ($/Bbl)

 

98.61

 

94.41

 

Average realized NGL price to NYMEX percentage

 

31

%

28

%

 

Our average realized oil price as a percentage of the average NYMEX price increased to 96% for the three months ended March 31, 2014 as compared to 90% for the three months ended March 31, 2013. All of our oil

 

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contracts are impacted by the NYMEX differential, which was negative $4.01 per Bbl for the three months ended March 31, 2014 as compared to negative $9.76 per Bbl for the three months ended March 31, 2013. Our average realized natural gas price as a percentage of the average NYMEX price was 82% for the three months ended March 31, 2014 and 79% for the three months ended March 31, 2013.

 

Oil revenues increased 135% from $21.9 million for the three months ended March 31, 2013 to $51.5 million for the three months ended March 31, 2014 as a result of a $9.96 per Bbl increase in our average realized price for oil, compounded by an increase in oil production volumes of 285 MBbls. Our higher oil production was a result of increased production from our horizontal drilling program, the Spanish Trail Acquisition in September 2013, the Collins and Wallace Contributions in January 2014 and the acquisition of producing properties in Martin County in February 2014. This increase was partially offset by the partial sale of 80 producing wells to Resolute in March 2013, which accounted for approximately 40% of total production for the three months ended March 31, 2013.

 

Natural gas revenues increased 89% from $1.2 million for the three months ended March 31, 2013 to $2.2 million for the three months ended March 31, 2014 as a result of an increase in natural gas production volumes of 147 MMcf and a $1.12 per Mcf increase in our average realized natural gas price. Our increase in natural gas production was a result of increased production from our horizontal drilling program along with our Spanish Trail Acquisition in September 2013, the Collins and Wallace Contributions in January 2014 and the acquisition of producing properties in Martin County in February 2014 offset by the partial sale of 80 producing wells to Resolute in March 2013, which accounted for approximately 40% of total production for the three months ended March 31, 2013.

 

NGL revenues increased 160% from $1.6 million for the three months ended March 31, 2013 to $4.1 million for the three months ended March 31, 2014 as a result of a $4.67 per Bbl increase in our average realized NGL price and a 120% increase in production. Our higher average realized NGL price and higher production was due to the recent expansion of the processing capacity of Coronado Midstream, LLC’s gas processing plant.

 

Operating Expenses. The following table summarizes our expenses for the periods indicated:

 

 

 

Three Months Ended
March 31,

 

 

 

 

 

 

 

2014

 

2013

 

$ Change

 

% Change

 

Operating expenses (in thousands, except percentages):

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

7,063

 

$

3,355

 

$

3,708

 

111

%

Production and ad valorem taxes

 

3,876

 

1,636

 

2,240

 

137

%

Depreciation, depletion and amortization

 

16,361

 

10,202

 

6,159

 

60

%

Asset retirement obligation accretion

 

29

 

25

 

4

 

16

%

Exploration expense

 

756

 

63

 

693

 

1,100

%

General and administrative expenses

 

17,016

 

555

 

16,461

 

2,966

%

Total operating expenses before gain on sale of assets

 

$

45,101

 

$

15,836

 

$

29,265

 

185

%

(Gain) on sale of assets

 

 

(6,129

)

6,129

 

NM

 

Total operating expenses after gain on sale of assets

 

45,101

 

9,707

 

35,394

 

365

%

Expenses per Boe:

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

9.15

 

$

8.60

 

0.55

 

6

%

Production and ad valorem taxes

 

5.02

 

4.19

 

0.83

 

20

%

Depreciation, depletion and amortization

 

21.19

 

26.16

 

(4.97

)

(19

)%

Exploration expense

 

0.98

 

0.16

 

0.82

 

513

%

Asset retirement obligation accretion

 

0.04

 

0.06

 

(0.02

)

(33

)%

General and administrative expenses

 

22.04

 

1.42

 

20.62

 

1,452

%

Total operating expenses per Boe

 

$

58.42

 

40.59

 

$

17.83

 

44

%

 

Lease Operating Expenses.  Lease operating expenses increased 111% from $3.4 million for the three months ended March 31, 2013 to $7.1 million for the three months ended March 31, 2014. The increase in our lease operating expense was attributable to the increase in production in the 2014 period along with higher workover costs, as we performed more workovers in the current period primarily related to wells affected by severe winter weather in the previous quarter.

 

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Production and Ad Valorem Taxes. Production and ad valorem taxes increased 137% from $1.6 million for the three months ended March 31, 2013 to $3.9 million for the three months ended March 31, 2014 primarily as a result of higher wellhead revenues.

 

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense increased 60% from $10.2 million for the three months ended March 31, 2013 to $16.4 million for the three months ended March 31, 2014 mainly due to increased production and the property acquisitions in conjunction with the IPO.  The DD&A rate decreased 19% from $26.16 per Boe for the three months ended March 31, 2013 to $21.19 per Boe for the three months ended March 31, 2014 due to the increase in our proved reserves associated with contributed properties more than offsetting the amount of the purchase price of these assets that is allocated to our depletable property pool.

 

Exploration Expenses. Exploration expense increased by $0.7 million from less than $0.1 million for the three months ended March 31, 2013 to $0.8 million for the three months ended March 31, 2014 due to additional activity in the 2014 period.

 

General and Administrative Expenses. General and administrative (“G&A”) expenses increased from $0.6 million for the three months ended March 31, 2013 to $17.0 million for the three months ended March 31, 2014 primarily due to increases in expensing non-cash incentive unit compensation and equity-based compensation and increases in compensation expense associated with additions to personnel.

 

Gain on Sale of Assets. Gain on sale of assets was $6.1 million for the three months ended March 31, 2013 as a result of the property sale to Resolute in March 2013. There were no asset sales in the three months ended March 31, 2014.

 

Other Income and Expenses. The following table summarizes our other income and expenses for the periods indicated:

 

 

 

Three Months Ended
March 31,

 

 

 

 

 

 

 

2014

 

2013

 

$ Change

 

% Change

 

Other income (expense) (in thousands, except percentages):

 

 

 

 

 

 

 

 

 

Other income

 

$

310

 

$

199

 

$

111

 

56

%

Loss on derivative instruments

 

(4,153

)

(1,657

)

(2,496

)

151

%

Interest expense

 

(1,131

)

(624

)

(507

)

81

%

Total other income (expense)

 

$

(4,974

)

$

(2,082

)

$

(2,892

)

139

%

 

Other Income. Other income increased 56% from $0.2 million for the three months ended March 31, 2013 to $0.3 million for the three months ended March 31, 2014 primarily due to an increase in income related to water we sourced and sold to other working interest partners for use in completion activities.

 

Loss on Derivative Instruments. During the three months ended March 31, 2013, we recorded a $1.7 million loss as compared to a $4.2 million loss in the three months ended March 31, 2014. The change was a result of the future commodity price outlook during the three months ended March 31, 2014 as compared to 2013.

 

Interest Expense. During the three months ended March 31, 2013, we recorded $0.6 million of interest expense as compared to $1.1 million in the three months ended March 31, 2014. The change was primarily the result of additional borrowings of $1.2 million under our revolving credit facility in the 2014 period.

 

Capital Requirements and Sources of Liquidity

 

Historically, the Company’s primary sources of liquidity have been capital contributions from its equity sponsor, borrowings under its revolving credit facility, term loan borrowings, proceeds from asset dispositions, proceeds from the issuance of net profits interests and cash flows from operations. To date, the Company’s primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties.

 

Our 2014 capital budget for drilling, completion, recompletion and infrastructure is approximately $365 million. We intend to allocate our 2014 capital budget approximately as follows:

 

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·                  $310 million, or 85%, for the drilling and completion of operated wells;

·                  $40 million, or 11%, for our participation in the drilling and completion of non-operated wells; and

·                  $15 million, or 4%, for infrastructure.

 

During the first quarter of 2014, we spent approximately $64 million on drilling, completion and capitalized workovers and $2 million on infrastructure.

 

Because we are the operator of a high percentage of our acreage, the amount and timing of these capital expenditures are largely discretionary. We could choose to defer a portion of these planned 2014 capital expenditures depending on a variety of factors, including the success of our drilling activities; prevailing and anticipated prices for oil, natural gas and NGLs; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; drilling, completion and acquisition costs; and the level of participation by other working interest owners.

 

We used a portion of the net proceeds from the IPO to fully repay our term loan and outstanding borrowings under our revolving credit facility. As of March 31, 2014, we have $140 million available under our revolving credit facility. Our borrowing base under our revolving credit facility is $300 million as of March 31, 2014.

 

Based upon current oil and natural gas price expectations for 2014, we believe that our cash flow from operations and additional borrowings under our revolving credit facility will provide us with sufficient liquidity to execute our current capital program. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. We cannot assure you that operations and other needed capital will be available on acceptable terms or at all. In the event we make additional acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital. If we require additional capital for that or other reasons, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. We cannot assure you that needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling program, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or replace our reserves.

 

Working Capital

 

Our working capital, which we define as current assets minus current liabilities, totaled negative $1.9 million and $16.3 million at March 31, 2014 and December 31, 2013, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $10.7 million and $13.2 million at March 31, 2014 and December 31, 2013, respectively. Due to the amounts that accrue related to our drilling program, we may incur working capital deficits in the future. We expect that our cash flows from operating activities and availability under our revolving credit facility will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil and natural gas production will be the largest variables affecting our working capital.

 

Contractual Obligations

 

We had no other material changes in our contractual commitments and obligations from amounts listed under “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Requirements and Sources of Liquidity—Contractual Obligations” in our Annual Report on Form 10-K for the year ended December 31, 2013.

 

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Cash Flows

 

The following table summarizes our cash flows for the periods indicated:

 

 

 

Three Months Ended March 31,

 

 

 

2014

 

2013

 

 

 

(In thousands)

 

Net cash provided by operating activities

 

$

31,001

 

$

14,585

 

Net cash provided by (used in) investing activities

 

(178,824

)

58,357

 

Net cash provided by (used in) financing activities

 

145,326

 

(94,456

)

 

Net cash provided by operating activities was approximately $31.0 million and $14.6 million for the three months ended March 31, 2014 and 2013, respectively. Revenues increased for the three months ended March 31, 2014 as compared to the three months ended March 31, 2013.  This increase was due to increased production related to properties acquired in the first quarter of 2014.

 

Net cash used in investing activities was approximately $178.8 million for the three months ended March 31, 2014, and net cash provided by investing activities for the three months ended March 31, 2013 was approximately $58.4 million. The increase in the amount of cash used in investing activities in the three months ended March 31, 2014 compared to the three months ended March 31, 2013 was due to capital expenditures totaling $177.5 million. These included the purchase of oil and gas assets for $80.0 million and $31.7 million for partial consideration of certain working interests in oil and gas properties contributed in conjunction with the IPO in the first quarter of 2014, offset by $115.3 million received from the sale of properties to Resolute in March 2013.

 

Net cash provided by financing activities was approximately $145.3 million for the three months ended March 31, 2014 and net cash used in financing activities for the three months ended March 31, 2013 was approximately $94.5 million. For the three months ended March 31, 2014, the increased cash provided by financing activities was primarily the result of capital contributions received in connection with the IPO.

 

Our Term Loan and Revolving Credit Facility

 

On September 10, 2013, in conjunction with the Spanish Trail Acquisition, the Company amended and restated its credit agreement, dated December 15, 2010, with Comerica Bank, as administrative agent, and expanded its syndicated bank group to 11 lenders and entered into a new term loan in the amount of $70 million, which was fully repaid in January 2014 with proceeds from the IPO.  The borrowing base under the Company’s amended and restated credit agreement is $300 million as of March 31, 2014, with lender commitments of $500 million, and the sublimit for letters of credit is $10 million.

 

The amount available to be borrowed under our revolving credit facility is subject to a borrowing base that is redetermined semiannually each May and November and depends on the volumes of our proved oil and natural gas reserves, estimated cash flows from these reserves and our commodity hedge positions. As of March 31, 2014, we had $110.0 million of borrowings and $0.6 million of letters of credit outstanding under our revolving credit facility. Our revolving credit facility matures September 10, 2017.

 

Our revolving credit facility is secured by liens on substantially all of our properties and guarantees from our subsidiaries other than any subsidiary that we have designated as an unrestricted subsidiary.

 

Our revolving credit facility contains restrictive covenants and minimum financial ratios, which are described in Note 6 to the consolidated financial statements. We were in compliance with such covenants and ratios as of March 31, 2014.

 

Critical Accounting Policies and Estimates

 

Please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our Annual Report on Form 10-K for the year ended December 31, 2013 for a description of the Company’s critical accounting policies.

 

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Equity-Based Compensation

 

In connection with the IPO, the Company adopted the RSP Permian, Inc. 2014 Long Term Incentive Plan (the “LTIP”) for the employees, consultants and directors of the Company and its affiliates who perform services for the Company.  See “Part III, Item 11. Executive Compensation” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 for additional information related to the LTIP. The valuation and expense recognition of equity-based compensation requires the use of estimates.

 

Income Taxes

 

The Company became a taxable entity as a result of its conversion from a limited liability company to a corporation on January 23, 2014.  Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of enacted tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At March 31, 2014, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.

 

Off-Balance Sheet Arrangements

 

As of March 31, 2014, we did not have any off-balance sheet arrangements.

 

Item 3.         Quantitative and Qualitative Disclosures About Market Risk.

 

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

 

Commodity Price Risk

 

Our revenues are subject to market risk and are dependent on the pricing that we receive for our oil, natural gas and NGL production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. Our realized prices are primarily driven by the prevailing prices for oil and the prevailing spot prices for natural gas and NGLs. We use derivative contracts to reduce our exposure to the changes in the prices of these commodities. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with projected production levels. We do not use these instruments to engage in trading activities, and we do not speculate on commodity prices.

 

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Our open positions as of March 31, 2014 were as follows:

 

Description & Production Period

 

Volume (Bbls)

 

Weighted
Average
Floor price
($/Bbl)(1)

 

Weighted
Average
Ceiling price
($/Bbl)(1)

 

Weighted
Average
Swap price
($/Bbl)(1)

 

Crude Oil Swaps:

 

 

 

 

 

 

 

 

 

April 2014 — December 2014

 

90,000

 

$

 

$

 

$

96.40

 

April 2014 — December 2015

 

210,000

 

 

 

92.60

 

 

 

 

 

 

 

 

 

 

 

Crude Oil Collars:

 

 

 

 

 

 

 

 

 

April 2014 — September 2014

 

6,000

 

$

85.00

 

$

113.04

 

$

 

April 2014 — December 2014

 

738,000

 

85.79

 

102.11

 

 

April 2014 — December 2015

 

525,000

 

85.00

 

95.00

 

 

January 2015 — December 2015

 

72,000

 

80.00

 

93.25

 

 

July 2014 — September 2014

 

90,000

 

90.00

 

101.50

 

 

October 2014 — December 2014

 

90,000

 

90.00

 

97.33

 

 

January 2015 — March 2015

 

120,000

 

90.00

 

92.53

 

 

 


(1)         The crude oil derivative contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude.

 

Description & Production Period

 

Volume
(MMBtu)

 

Weighted
Average
Floor price
($/MMBtu)(1)

 

Weighted
Average
Ceiling price
($/MMBtu)(1)

 

Weighted
Average
Swap price
($/MMBtu)(1)

 

Natural Gas Collars:

 

 

 

 

 

 

 

 

 

April 2014 — December 2014

 

1,350,000

 

$

4.00

 

$

4.78

 

$

 

 


(1)         The natural gas derivative contracts are settled based on the NYMEX closing settlement price.

 

The fair value of our derivative contracts as of March 31, 2014 was a net liability of $3.7 million. For information regarding the terms of these hedges, see “Part I, Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operations—How We Evaluate Our Operations—Realized Prices on the Sale of Oil, Natural Gas and NGLs” above.

 

Counterparty and Customer Credit Risk

 

Our commodity derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as it deems appropriate. We plan to continue to evaluate the credit standings of our counterparties in a similar manner. The counterparties to our derivative contracts currently in place have investment grade ratings.

 

Our principal exposures to credit risk are through receivables arising from joint operations and receivables from the sale of our oil and natural gas production due to the concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit quality of our customers is high.

 

Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.

 

Interest Rate Risk

 

At March 31, 2014, we had $110.0 million of debt outstanding that is subject to interest rate risk, with an assumed weighted average interest rate of 1.7%. Assuming no change in the amount outstanding, the impact on interest expense of a 1.0% increase or decrease in the assumed weighted average interest rate would be approximately $1.1 million per year. We currently do not engage in any interest rate hedging activity.

 

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Item 4.         Controls And Procedures.

 

Evaluation of Disclosure Controls and Procedures

 

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2014. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2014 at the reasonable assurance level.

 

Changes in Internal Control over Financial Reporting

 

As described above, there were no changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the three months ended March 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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Table of Contents

 

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings.

 

From time to time, we are party to ongoing legal proceedings in the ordinary course of business, including workers’ compensation claims and employment related disputes.  While the outcome of these proceedings cannot be predicted with certainty, we do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations or liquidity.

 

Item 1A.  Risk Factors.

 

In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the factors discussed in “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013, which could materially affect our business, financial condition or future results.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or results of operations.

 

Item 6.  Exhibits.

 

See Exhibit Index on page 42 of this Quarterly Report on Form 10-Q.

 

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

RSP PERMIAN, INC.

 

 

 

 

 

By:

/s/ Scott McNeill

 

 

Scott McNeill

 

 

Chief Financial Officer and Director

 

 

(Principal Financial Officer)

 

Date:

May 14, 2014

 

 

 

 

 

 

 

By:

/s/ Barry S. Turcotte

 

 

Barry S. Turcotte

 

 

Chief Accounting Officer

 

 

(Principal Accounting Officer)

 

Date:

May 14, 2014

 

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Table of Contents

 

EXHIBIT INDEX

 

Exhibit No.

 

Description

3.1

 

Amended and Restated Certificate of Incorporation of RSP Permian, Inc. (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 29, 2014).

3.2

 

Amended and Restated Bylaws of RSP Permian, Inc. (incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 29, 2014).

4.1

 

Registration Rights Agreement, dated as of January 23, 2014, among RSP Permian, Inc., RSP Permian Holdco, L.L.C., Ted Collins, Jr., Wallace Family Partnership, LP, ACTOIL, LLC, Rising Star Energy Development Co., L.L.C. and Pecos Energy Partners, L.P. (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on January 29, 2014).

4.2

 

Stockholders’ Agreement, dated as of January 23, 2014, among RSP Permian, Inc., RSP Permian Holdco, L.L.C., Ted Collins, Jr., Wallace Family Partnership, LP, Rising Star Energy Development Co., L.L.C. and Pecos Energy Partners, L.P. (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on January 29, 2014).

10.1

 

Amended and Restated Limited Liability Company Agreement of RSP Permian Holdco, L.L.C., dated January 23, 2014 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 29, 2014).

10.2

 

RSP Permian, Inc. 2014 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 22, 2014).

10.3(a)

 

Form of Restricted Stock Grant and Award Agreement.

10.4

 

Form of Indemnification Agreement (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to RSP Permian, Inc.’s Registration Statement on Form S-1, filed on January 2, 2014, File No. 333-192268).

31.1(a)

 

Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, Rule 13a-14(a)/15d-14(a), by Chief Executive Officer.

31.2(a)

 

Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, Rule 13a-14(a)/15d-14(a), by Chief Financial Officer.

32.1(b)

 

Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Chief Executive Officer.

32.2(b)

 

Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Chief Financial Officer.

101.INS(c)

 

XBRL Instance Document.

101.SCH(c)

 

XBRL Taxonomy Extension Schema Document.

101.CAL(c)

 

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF(c)

 

XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB(c)

 

XBRL Taxonomy Extension Label Linkbase Document.

101.PRE(c)

 

XBRL Taxonomy Extension Presentation Linkbase Document.

 


(a)         Filed herewith.

(b)         Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference.

(c)          To be furnished by amendment within the 30-day grace period provided by Rule 405(a)(2) of Regulation S-T. Pursuant to Rule 406T of Regulation S-T, this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Exchange Act, and is otherwise not subject to liability under these sections.

 

 

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